ASU nitrogen sweep gas in hydrogen separation membrane for production of HRSG duct burner fuel

ABSTRACT

The present invention relates to the use of low pressure N2 from an air separation unit (ASU) for use as a sweep gas in a hydrogen transport membrane (HTM) to increase syngas H2 recovery and make a near-atmospheric pressure (less than or equal to about 25 psia) fuel for supplemental firing in the heat recovery steam generator (HRSG) duct burner.

CROSS REFERENCE TO RELATED APPLICATIONS

The present invention claims priority both to U.S. patent application Ser. No. 60/879,615, filed Jan. 10, 2007 and to U.S. patent application Ser. No. 60/925,800, filed Apr. 23, 2007, the entire contents of both applications incorporated herein by reference.

GOVERNMENT SUPPORT

The present invention was made in part with support from United States Department of Energy, contract no. DE-FC26-05NT42469. Accordingly, the United States Government may have certain rights to this invention.

FIELD OF THE INVENTION

The present invention relates to the use of low pressure N₂ from an air separation unit (ASU) as a sweep gas in a hydrogen transport membrane (HTM) to increase syngas H₂ recovery and make a near-atmospheric pressure (less than or equal to about 25 psia) fuel for firing in the heat recovery steam generator (HRSG) duct burner.

BACKGROUND OF THE INVENTION

Conventional IGCC carbon capture methods: The typical process for CO₂ capture in an integrated gasification combined cycle (IGCC) plant is well known in the industry. Coal is gasified with O₂ at high pressures to produce syngas that is then scrubbed, cleaned, and stripped of CO₂ before it is combusted in a gas turbine. Typically, the CO₂ is removed from the syngas stream via a physical sorbent like Selexol® or Rectisol®.

The syngas is contacted with lean solvent in a scrubber column where the sorbent absorbs the CO₂ and is regenerated by flashing CO₂ at successively lower and lower pressures. The low pressure CO₂ is compressed to supercritical pressure for sequestration. In this scenario, the CO₂ sequestration cost is high because Selexol®-type plants have high capital costs and the CO₂ must be pressurized to greater than about 2000 psia from pressures as low as 18 psia.

Carbon capture in IGCC plants with hydrogen membranes: A different approach for syngas processing is to use a hydrogen transport membrane (HTM) to remove H₂ from the syngas and leave a CO₂-rich stream that can be purified and compressed to supercritical pressure from near-gasifier (e.g., about 350 to 1000 psia) pressure. One way to minimize membrane capital and fuel compression costs in this scenario is to use compressed ASU N₂ as a permeate sweep stream to provide a H₂—N₂ fuel mixture for a gas turbine feed. Compressed N₂ sweep decreases H₂ permeate partial pressure and minimizes the required membrane area. It also eliminates the need to compress the gas turbine fuel, reduces NO_(x) emissions, and improves gas turbine performance. This approach is not currently used in industrial practice and it is described in more detail below. While an IGCC plant with carbon capture that utilizes HTM technology may be cost competitive with plants that employ traditional carbon capture methods, there are several issues that may arise in these plant designs. For example, even at high syngas H₂ recovery, there is a significant amount of H₂ in the membrane retentate that must be removed from the CO₂-rich stream for it to be sequestered. Costs related to CO₂ purification and compression increase with increasing H₂ in the CO₂-rich stream.

In addition, in an IGCC plant that produces both electricity and H₂, there is often not enough heat in the gas turbine exhaust to superheat the steam that is generated in the IGCC process. It is therefore necessary to fire supplemental fuel in the heat recovery steam generator (HRSG) duct burner to superheat the steam for expansion in the steam turbine.

SUMMARY OF THE INVENTION

In accordance with the present invention, we have developed systems and methods by which low pressure (LP) ASU N₂ (for example, less than or equal to about 75 psia) is used as a HTM permeate sweep stream to increase overall syngas H₂ recovery and make a near-atmospheric pressure (for example, less than or equal to about 25 psia) fuel for firing in the HRSG duct burner.

In an IGCC plant that has CO₂ capture, compressed ASU N₂ is used as HTM permeate sweep to produce a fuel for the gas turbine combustor that will minimize NO_(x) production. In this invention, low pressure (LP) ASU N₂ sweep is used in a second HTM to recover additional H₂ and make near-atmospheric pressure fuel gas for firing in the HRSG duct burner. The use of ASU N₂ sweep decreases H₂ permeate partial pressure and increases flux while burning a H₂—N₂ fuel mixture in both the gas turbine and the duct burner helps to control NO_(x) emissions. Also, increasing H₂ recovery from the syngas decreases the amount of processing required to purify and sequester the CO₂-rich membrane retentate, and firing a near-atmospheric pressure H₂—N₂ fuel mixture in the HRSG duct burner increases process efficiency. In an IGCC plant where electricity and H₂ are both produced, burning a near-atmospheric pressure H₂—N₂ fuel mixture in the HRSG duct burner eliminates the need to supplementary fire depressurized syngas in order to superheat the steam for expansion in the steam turbine.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention and the advantages thereof, reference should be made to the following Detailed Description taken in conjunction with the accompanying drawings in which:

FIG. 1 is a schematic process flow diagram (PFD) illustrating a power-only IGCC plant with carbon capture and HTMs. The second HTM uses low pressure (LP) ASU N₂ as a sweep gas to make near-atmospheric pressure fuel for the HRSG duct burner.

FIG. 2 is a graph illustrating HTM retentate and permeate H₂ partial pressure as a function of normalized membrane area from the hydrogen transport membrane for the gas turbine fuel (HTM-GT). In the Example, the retentate side total feed pressure is 500 psia and the permeate side total feed pressure is 385 psia. The two streams are in counter-current flow with one another.

FIG. 3 is a graph illustrating HTM retentate and permeate H₂ partial pressure as a function of normalized membrane area from the hydrogen transport membrane for the duct burner fuel (HTM-DB). In the Example, the retentate side and permeate side total feed pressures are 490 psia and 25 psia, respectively. The streams are in counter-current flow with one another.

FIG. 4 is a schematic process flow diagram (PFD) illustrating three HTMs arranged in series for production of high-purity H₂, gas turbine fuel, and HRSG duct burner fuel in an IGCC plant with carbon capture. The portions of the IGCC plant upstream and downstream of the HTMs are the same as shown in FIG. 1.

FIG. 5 is a schematic process flow diagram (PFD) illustrating an alternative arrangement for the HTMs in an IGCC plant where both electricity and H₂ are produced. The HTM for production of high-purity H₂ (HTM-H₂) and HTM-GT are arranged in parallel in FIG. 5 instead of in series as in FIG. 4. Note that the stream conditions given in Table 2 do not apply to this case.

DETAILED DESCRIPTION OF THE INVENTION

In an IGCC plant where CO₂ capture is necessary, compressed ASU N₂ (for example, equal to or greater than about 125 psia) can be used as an HTM permeate sweep to produce a fuel for the gas turbine combustor that will minimize NO_(x) production. In accordance with the present invention, low pressure (LP) ASU N₂ (for example, less than or equal to about 75 psia) sweep is used in a second HTM to recover additional H₂ and make near-atmospheric pressure fuel gas for firing in the HRSG duct burner. The use of ASU N₂ sweep decreases H₂ permeate partial pressure and increases flux for both HTMs while burning a H₂—N₂ fuel mixture in both the gas turbine and the duct burner helps to minimize NO_(x) emissions. Increasing H₂ recovery from the syngas by using a hydrogen transport membrane for duct burner fuel (HTM-DB) decreases the amount of processing required to purify and sequester the CO₂-rich membrane retentate, and firing a near-atmospheric pressure H₂—N₂ fuel mixture in the HRSG duct burner increases process efficiency.

In some embodiments of the present invention in which an IGCC plant produces both electricity and H₂, burning a low pressure (i.e., near atmospheric) H₂—N₂ fuel mixture in the HRSG duct burner can eliminate the need to supplementary fire depressurized syngas in order to superheat the steam for expansion in the steam turbine.

The prior art describes IGCC plants with CO₂ capture that utilize compressed ASU N₂ as sweep gas in a HTM to make gas turbine combustor fuel. The present invention, however, provides for the use of low pressure ASU N₂ sweep to make a near-atmospheric pressure H₂—N₂ fuel mixture for combustion in the HRSG duct burner. The production of a low pressure H₂—N₂ fuel mixture increases the total H₂ recovery from the syngas and decreases the size and complexity of the CO₂ purification processing downstream. Also, since a significant quantity of steam is generated in an IGCC plant that must be superheated for steam turbine expansion, the extra energy available to the HRSG from the firing of low pressure fuel adds flexibility to plant operation. In one computer-simulated example in a power-only scenario (i.e. without high-purity H₂ production), process efficiency and net power output can increase by about 0.6% if a low pressure H₂—N₂ fuel mixture is fired in the HRSG duct burner.

In an IGCC plant that produces both H₂ and electricity, there may not be enough heat available in the gas turbine exhaust to superheat all the steam in the HRSG. The only other available high level heat is at the exit of the gasifier where it is impractical to superheat the steam because of the severity of the process gas. In this case, combustion of the low pressure H₂—N₂ fuel mixture in the HRSG duct burner is a better option than firing gasifier syngas or low pressure H₂ product to superheat the steam.

Furthermore, the present invention is expected to provide economic advantages over the prior art. In one computer-simulated example for a power-only IGCC plant scenario, analysis shows about $1/MWh cost of electricity (about $2 MM/yr for 280 MW plant) savings for the case that uses a LP ASU N₂ swept HTM to make near-atmospheric fuel mixture for firing in the HRSG duct burner. The extra capital needed for the additional membrane area can be offset by capital savings from the simplification of the CO₂ purification processing.

To illustrate the present invention, reference is had to the following examples.

EXAMPLE 1 Power-Only IGCC Plant with CO₂ Capture

FIG. 1 shows a simplified process flow diagram (PFD) for an embodiment of the present invention in which a power-only (i.e. without high-purity H₂ production) IGCC plant with CO₂ capture utilizes HTM technology to make a H₂—N₂ fuel mixture for combustion in the gas turbine and the HRSG duct burner. The portions of the plant representing aspects of the present invention are drawn with dashed lines and/or labeled with bold font in the diagram. While not to be construed as limiting, an exemplary stream summary is given in Table 1 for the computer-simulated example case described below.

TABLE 1 Stream summary for PFD shown in FIG. 1. Stream 9 3 15 23 39 47 49 29 43 Flow (lbmol/hr) 5809 26160 38680 21270 20530 12700 37680 1592 Flow (kpph) 268.1 187.1 526.5 713.6 678.6 677.1 546.3 607.1 25.6 Temp (F.) 1971 750 750 750 100 750 750 Pressure (psia) 615 500 490 485 2200 375 20 H₂ (%) 32.0 47.3 4.1 0.6 1.0 45.6 45.6 CO (%) 39.9 1.3 2.4 2.5 0.5 0.0 0.0 CO₂ (%) 11.0 29.9 54.4 56.3 95.3 0.0 0.0 H₂O (%) 13.7 20.2 36.7 38.0 0.0 0.6 0.6 N₂ (%) 1.5 1.0 1.8 1.9 3.1 53.6 53.6 Other (%) 1.9 0.3 0.6 0.7 0.1 0.2 0.2

As shown in FIG. 1, air 1 is fed into an ASU 100 where it is separated into O₂ 3, N₂ streams 5 and 6, and unused products 7. The O₂ 3 is compressed in compressor 102 and fed to the gasifier 104 where it is reacted with a slurry 13 (made from coal 9 and water 11 in mixer 106) to form raw syngas 15 and slag 16. In this example, a Conoco-Philips E-Gas® gasifier is modeled for unit 104 that operates at 615 psia and 1970° F.

The raw syngas 15 exiting gasifier 104 is sent to the syngas processing portion of the plant 108 where it is cooled by generating steam 17 from boiler feed water 19. The steam 17 is sent to the heat recovery steam generator (HRSG) 110 for use in the steam turbine 112 steam cycle. Impurities 21 in the raw syngas stream that must be removed could include heavy metals, halides, particulate matter, and/or sulfur-containing compounds. Impurity removal may be accomplished via traditional cold gas cleanup technology in this example, but advanced warm gas cleanup technologies may also be used. To maximize IGCC efficiency and the extent of carbon capture, it is preferred that the syngas processing method be designed such that the impurities are separated without capturing carbon-containing species or H₂.

The water gas shift (WGS) reactors, which are also included in the syngas processing portion of the IGCC plant 108 shown in FIG. 1, convert H₂O and CO into H₂ and CO₂. The WGS reactors are needed to maximize H₂ content in the membrane feed and minimize the amount of CO₂ purification necessary for sequestration. In this particular example, a two-stage WGS reactor design is used. Computer simulation analysis shows that a design for this Example that uses a high temperature shift reactor (HTS) in series with a medium temperature shift reactor (MTS) is preferred over a design with two high temperature shift reactors in series.

The stream 23 exiting the syngas processing portion of the plant 108 is predominantly made up of H₂, CO₂, and H₂O and is fed to hydrogen transport membrane (HTM-GT) 114 at near-gasifier pressure (for example, about 350 to 1000 psia). For this study, the hydrogen membrane 116 is a dense transition metal membrane (such as Nb or Ta) that is coated with Pd catalyst on the surface. The Pd catalyzes the dissociation of H₂ molecules into H atoms on the syngas side 118 of the membrane. The H atoms then diffuse through the bulk metal to the permeate 120 where Pd catalyzes the re-association of H atoms into H₂ molecules that desorb into the bulk gas. This arrangement gives high H₂ flux at near 100% selectivity. The advantage of using metals like Nb or Ta for the bulk membrane is that they have high proton flux but cost much less than Pd. However, the membrane surface should be coated with Pd because the bulk metal is not an efficient catalyst for H₂ dissociation. It should also be noted that any membrane material(s) with reasonable H₂ flux and selectivity would suffice in an IGCC plant for power production. One skilled in the art will appreciate that reasonable H₂ flux and selectivity can be determined based on design conditions, processing and economic factors. While not to be construed as limiting, alternative HTMs for use in the present invention could include membranes having H₂-selective material formed of one or more of the following: supported or unsupported porous ceramics, dense cermets, dense metals, and/or dense metal alloys.

As used in this Example, ASU N₂ 6 emerges from ASU 100 at about 190 psia, while ASU N₂ 5 emerges from the ASU at about 60 psia. A portion of ASU N₂ 5 becomes stream 41. The remaining portion 201 of ASU N₂ 5 is compressed in compressor 119 to about 190 psia to form stream 203, which is then combined with ASU N₂ 6 to form stream 25. ASU N₂ 25 is compressed in compressor 121 in this example to 385 psia and used as HTM-GT 114 permeate sweep 27 in counter-current flow with the syngas feed 23. N₂ is used as a permeate sweep stream to decrease H₂ partial pressure, increase H₂ flux across the membrane 116, reduce the required membrane area, improve gas turbine 122 performance by increasing the mass flow and molecular weight of the expanding gas, and control the turbine inlet temperature to reduce NO_(x) emissions. The H₂ partial pressure profile in HTM-GT 114 in this Example is shown in FIG. 2. In this example, there is a total pressure drop of 10 psi in the direction of the flow in both the retentate 118 and permeate 120 and the H₂ recovery is 95%. The flow of the sweep gas 27 is set such that the lower heating value (LHV) of the resulting H₂—N₂ fuel mixture 29 is 125 BTU/scf in order to minimize adiabatic flame temperature and NO_(x) production in the gas turbine combustor 124. The H₂ content in the fuel 29 is 45.6 vol % as shown in Table 1. In some cases, it may be possible to increase the N₂ sweep flow 27 and decrease the resulting fuel 29 LHV below 125 BTU/scf.

Since pressurized N₂ is used as sweep gas 27, the HTM-GT 114 permeate 29 can be directly fed to the gas turbine combustor 124 without further compression. In this example, a General Electric Co. (GE) 7251FB gas turbine 122 generates 230 MW of electrical power from 607.1 thousand pounds per hour (kpph) of fuel 29 and compressed air 30. After expansion, 3770 kpph of exhaust 31 at 1146° F. is sent to the HRSG 110 to generate high pressure steam 33, intermediate pressure steam reheat 35 and low pressure steam 37 for the steam turbine.

In this example, the H₂ partial pressure in the HTM-GT 114 retentate 39 is 20 psia (see FIG. 2). Eighty-five percent of the remaining H₂ is recovered by feeding the H₂-depleted syngas 39 from HTM-GT 114 into a second HTM 126 (i.e. HTM-DB) that uses LP ASU N₂ 41 as a permeate sweep stream. The permeate produced 43 from this HTM 126 is a near-atmospheric pressure (for example, less than or equal to about 25 psia) mixture of H₂ and N₂ that can be combusted in the HRSG duct burner 132 to increase the temperature of the gas turbine exhaust 31 and increase the heat available in the HRSG 110. The N₂ sweep 41 flow rate to HTM-DB 126 is set such that duct burner fuel 43 LHV is 125 BTU/scf (45.6 vol % H₂) in order to minimize additional NO_(x) emissions from the HRSG stack 45. The H₂ partial pressure profile in HTM-DB 126 is shown in FIG. 3. HTM-DB 126 generates 25.6 kpph of H₂—N₂ fuel mixture 43 exiting from permeate 130 of HTM-DB 126 that is burned in the HRSG duct burner 132 to increase the gas temperature in the HRSG 110 from 1146 to 1209° F. The net process efficiency increases from 32.7 to 32.9% (HHV basis) when HTM-DB 126 is used. If it is available, the N₂ sweep flow 41 could be increased such that the LHV of the H₂—N₂ fuel mixture 43 is as low as 90 BTU/scf. This is possible because there is a longer residence time for combustion in the HRSG 110.

Membrane 129 of HTM-DB 126 preferably has high (approaching 100%) H₂ permeation selectivity (e.g. the dense, Pd-coated membrane described above) and flux. Those skilled in the art will appreciate that other HTMs such as those described hereinabove may be suitable for use in accordance with the present invention so long as the desired H₂ flux and selectivity are met.

The retentate stream 47 exiting retentate side 128 of HTM-DB 126 is CO₂-rich at near-gasifier pressure (for example, about 350-1000 psia). Before this stream 47 can be sequestered, it must be purified, dried, and compressed in the CO₂ processing portion of the IGCC plant 134 to produce sequesterable CO₂ 49 and waste 51 (e.g., knockout water for catox-based systems) as shown in FIG. 1. Options for CO₂ purification in 134 include, but are not limited to, catalytic oxidation of residual combustibles with ASU O₂ or CO₂ separation via partial condensation. The CO₂ purification process can be simplified when HTM-DB 126 is used because there is less H₂ to be removed from the CO₂-rich stream 47.

It is believed that the best mode for CO₂ purification in the examples cited herein is by oxidizing residual combustibles in one or more catalytic oxidation (catox) reactor(s) with ASU O₂. There are several reasons including: O₂ is readily available and already being produced on-site with an ASU, the extra capacity required for the catox reactor is less than or equal to about 10% of the O₂ required for the gasifier, and there are advantages to the process heat integration with the catox unit because the high-level heat generated in the oxidation reactions can be used elsewhere in IGCC plant. In addition, there are also anticipated impurities issues with some alternative methods.

Those skilled in the art will appreciate that the example provided above and the example that follows are intended to be illustrative of the invention and are not to be construed as limiting. Those skilled in the art will also appreciate that the flow, compositions, temperature and pressure ranges as well as heating values and equipment given in the examples are likewise for purposes of illustration. Such examples and parameters could be altered in accordance with the present invention depending on process, equipment, economic considerations and the like. For example, one N₂ stream could be withdrawn from ASU 100 rather than streams 5 and 6 (as shown in FIG. 1). This one stream could then subsequently be divided into two streams or portions of N₂ (with appropriate compression as needed) for use as the N₂ sweep gas streams.

EXAMPLE 2 Co-Production of H₂ and Electrical Power in an IGCC Plant with CO₂ Capture

An exemplary arrangement of HTMs for co-production of H₂ (e.g., high-purity H₂) and electrical power in an IGCC plant with CO₂ capture in accordance with an alternative embodiment of the present invention is illustrated in FIG. 4. As used in the present invention, “high-purity H₂” gas, it is meant H₂ gas that is at least 95% by volume H₂. More preferably, such gas will be at least 99% by volume H₂ and most preferably, such gas will be greater than 99.9% by volume H₂. The process flow diagram (PFD) only shows the portions for the HTMs of the IGCC plant. The processing and equipment upstream and downstream of the HTMs can be the same as described above and shown in FIG. 1. The stream summary for this particular computer-simulated example is given in Table 2.

TABLE 2 Stream summary for PFD shown in FIG. 4. Stream 23 57 39 47 53 29 43 Flow (lbmol/hr) 38680 30290 23030 20520 8389 15710 5438 Flow (kpph) 713.6 696.7 682.1 677.0 16.9 253.1 87.6 Temp (F.) 750 750 750 750 750 750 750 Pressure (psia) 500 490 480 475 105 305 20 H₂ (%) 47.3 32.6 11.4 0.6 100.0 45.6 45.6 CO (%) 1.3 1.7 2.2 2.5 0.0 0.0 0.0 CO₂ (%) 29.9 38.2 50.2 56.3 0.0 0.0 0.0 H₂O (%) 20.2 25.8 33.9 38.1 0.0 0.6 0.6 N₂ (%) 1.0 1.3 1.7 1.9 0.0 53.6 53.6 Other (%) 0.3 0.4 0.6 0.6 0.0 0.2 0.2

In this particular case and as shown in FIG. 4, the H₂-product HTM 136, gas turbine fuel HTM 114, and duct burner fuel HTM 126 are arranged in series. Clean, shifted syngas 23 (same as stream 23 in FIG. 1 and Table 1) is fed to the syngas side 138 of HTM-H₂ 136 and H₂ 53 is removed from the permeate side of HTM-H₂ 136. For high-purity H₂ production 53, membrane 140 with high (near 100%) H₂ permeation selectivity (e.g. the dense, Pd-coated membrane described above) should be used in HTM-H₂ 136 without N₂ sweep in order to avoid the need for permeate 53 purification. Those skilled in the art will appreciate that other HTMs such as those described hereinabove may be suitable for use in accordance with the present invention so long as the desired H₂ flux and selectivity are met. The ideal H₂ permeate 53 pressure is determined by minimizing product costs as a function of membrane capital and parasitic H₂ compression loads. The H₂ is cooled in heat exchanger 141 by raising steam or heating process gas or cooling water before it can be compressed in compressor 142 and sent to the pipeline 55.

The retentate 57 from HTM-H₂ 136 is fed sequentially to HTM-GT 114 and retentate 39 to HTM-DB 126 where the H₂ is recovered to make fuel 29 for the gas turbine combustor 124 and fuel 43 for the HRSG duct burner 132 in a similar fashion as described above. The coal 9 (not shown) flow rate for this exemplary IGCC plant with co-production of power and H₂ is the same as the coal 9 flow rate for the previous power-only IGCC plant. A smaller gas turbine 122 is used in this Example of the co-production plant design so that a significant quantity of the H₂ can be used to make pipeline product 55 instead of power. Therefore, the gas turbine fuel flow rate in 29 is 253.1 kpph and the gas turbine exhaust flow 31 (not shown) decreases from 3770 to 1696 kpph. The gasifier 104, syngas processing 108, and CO₂ purification 134 portions of the IGCC plant are the same size as in Example 1 and generate the same amount of saturated steam 17 that must be superheated in the HRSG 110 for expansion in the steam turbine 112. Due to the decrease in mass flow in 31, the amount of heat available in 110 is much lower and supplemental firing of the HRSG duct burner 132 is critical to maximizing plant performance by avoiding uneconomical steam 17 export or pressure let-down.

There are other options for providing for the duct firing fuel aside from the near-atmospheric pressure H₂—N₂ fuel mixture described above. For instance, uncompressed H₂ product 53 could be burned instead of being sent to the pipeline, some of the syngas 23 could be throttled, or some of the high pressure H₂—N₂ fuel mixture turbine fuel 29 could be throttled. The low-pressure H₂—N₂ fuel mixture 43 made by HTM-DB 126 is the most efficient fuel because the maximum amount of energy from the coal 9 goes through the combined cycle and a high pressure fuel is not used where only low pressure is required. It also maximizes the extent of carbon capture possible and simplifies the CO₂ purification process 134.

There are yet other alternative configurations for the IGCC plant that could be used in conjunction with the HRSG duct burner fuel made in 126. For example, the clean, shifted syngas 23 could be cooled to 100° F. and the condensed water could be removed in a knock-out drum. Under these conditions, the H₂ content in dried stream 23 entering HTM-GT 114 feed increases and the H₂ partial pressure increases. In the power-only IGCC plant, this reduces membrane 116 area but also decreases the total high heating value (HHV) process efficiency. The cost of electricity produced is expected to decrease under these conditions because the sensitivity to membrane capital is higher than the sensitivity to process efficiency.

In the power-only example described above in Example 1, the recovery of H₂ from the syngas stream is 95% in HTM-GT 114 and 85% in HTM-DB 126. These values could be adjusted to reduce the cost of electricity.

Integration of water gas shift (WGS) catalyst into the syngas side 118 of HTM-GT 114 is commonly suggested in the literature to increase CO conversion. Though this is an option, sensitivity analysis shows that this is not the best mode for practice because it increases the cost of IGCC products. The amount of membrane area required for H₂ separation is minimized if the syngas CO is converted in high temperature and medium temperature shift units in 108 before it is fed to the HTMs.

In yet another embodiment of the present invention in which an IGCC plant is designed to produce both H₂ and electricity, HTM 136 and HTM 114 could be arranged in parallel as shown in FIG. 5. This is contrast to the embodiment of HTMs shown in FIG. 4 in which the HTMs are instead arranged in series. While the reference numerals in FIG. 5 correspond to those in FIG. 4, the stream conditions in Table 2 do not correspond to FIG. 5. Rather, stream conditions for FIG. 5 for this computer-simulated example are shown below in Table 3.

TABLE 3 Stream summary for PFD shown in FIG. 5. Stream 23 57 59 39 47 53 29 43 Flow (lbmol/hr) 38675 12691 8868 21559 20531 9857 15713 2224 Flow (kpph) 713.6 396.2 282.9 679.1 677.1 198.7 253.2 35.8 Temp (F.) 750 750 750 750 750 750 750 750 Pressure (psia) 500 490 490 490 485 25 305 20 H₂ (%) 47.3 6.3 4.1 5.4 0.7 100.0 45.6 45.6 CO (%) 1.3 2.3 2.4 2.4 2.5 0.0 0.0 0.0 CO₂ (%) 29.9 53.1 54.4 53.6 56.3 0.0 0.0 0.0 H₂O (%) 20.2 35.9 36.7 36.2 38.0 0.0 0.6 0.6 N₂ (%) 1.0 1.8 1.8 1.8 1.9 0.0 53.6 53.6 Other (%) 0.3 0.6 0.6 0.6 0.6 0.0 0.1 0.1

Simulation results indicate that the cost of H₂ product is almost equivalent if the HTMs are arranged in parallel or in series.

Other alternative configurations to consider for an IGCC plant where H₂ and electricity are both produced include: withdrawing permeate from HTM-H₂ 136 at more than one pressure. The membrane area required for H₂ recovery increases with increasing permeate pressure because the driving force decreases between the syngas and permeate. However, H₂ product compression costs decrease with increasing permeate pressure. The cost of the H₂ product may be minimized by withdrawing portions of the total H₂ product at different pressure levels.

In addition, the use of pressurized superheated steam as a sweep gas in HTM-H₂ 136 (FIGS. 4 and 5) can be considered for an IGCC plant in which both H₂ and electricity are produced. Similar to the use of compressed ASU N₂ as a sweep stream for gas turbine fuel, the use of pressurized superheated steam as a sweep gas in 136 could reduce or eliminate H₂ compression costs and reduce membrane area by decreasing the H₂ partial pressure in the permeate. In such a case, superheated steam could be taken from the HRSG 110 and fed as a sweep gas to HTM-H₂ 136. The H₂O/H₂ permeate is cooled, the condensed water is removed via a knock-out drum, and the H₂ is dried before it is sent to the pipeline. The condensed water is boiled and superheated in the HRSG or the IGCC process and recycled for use as HTM-H₂ sweep.

It may also be possible to use other diluents like superheated steam as permeate sweep gases in HTM-GT 114 or HTM-DB 126, but it is unlikely that this would be the most efficient scenario. If the H₂/H₂O fuel that is produced in the membrane is combusted in the gas turbine 122 or the HRSG duct burner 132, the latent heat of the steam exiting the stack of the HRSG 45 is not recovered.

Although the invention has been described in detail with reference to certain preferred embodiments, those skilled in the art will recognize that there are other embodiments for the processes and apparatus described hereinabove, and that such alternative processes and apparatus are within the spirit and the scope of the claims. 

What is claimed is:
 1. A process for H₂ recovery from a H₂-containing gas stream from a gasifier, the process comprising: feeding the H₂-containing gas stream to a first hydrogen transport membrane (HTM); feeding a first portion of nitrogen produced in an air separation unit (ASU) to the first HTM as a HTM permeate sweep stream; recovering a first H₂-N₂ fuel mixture from the first HTM and supplied to a gas turbine generator; feeding a retentate stream from the first HTM to a second hydrogen transport membrane (HTM); feeding a second portion of nitrogen produced in the ASU to the second HTM for use as a HTM permeate sweep stream; and recovering a second H₂-N₂ fuel mixture from the second HTM and supply as a fuel to a duct burner of a heat recovery steam generator.
 2. The process of claim 1, wherein the first portion of nitrogen is introduced into the first HTM at a pressure of equal to or greater than about 125 psia and wherein the second portion of nitrogen is introduced into the second HTM at a pressure of less than or equal to about 75 psia.
 3. The process of claim 1, wherein the second H₂-N₂ fuel mixture from the second HTM for use a duct burner fuel is at near atmospheric pressure of less than or equal to about 25 psia.
 4. The process of claim 1, wherein the H₂-containing gas stream fed to the first HIM is at near-gasifier pressure of between about 350 to 1000 psia.
 5. The process of claim 1, wherein the first and second HTMs each comprise a H₂-selective membrane selected from one or more of the following materials: supported or unsupported porous ceramics, dense cermets, dense metals, and/or dense metal alloys.
 6. An apparatus for increasing H₂ recovery from a H₂-containing gas stream from a gasifier, the apparatus comprising: an air separation unit (ASU) configured to provide a source of nitrogen; a first hydrogen transport membrane (HTM) configured to receive a portion of the ASU nitrogen as a first HTM permeate sweep stream and the H₂-containing stream to produce an H₂ fuel mixture and provide it as a fuel to a gas turbine engine; and a second hydrogen transport membrane (HTM) configured to receive a second portion of the ASU nitrogen as a second HTM permeate sweep stream and configured to receive retentate from the first HTM to produce a second H₂ fuel mixture to supply a burner of a heat recovery steam generator.
 7. The apparatus of claim 6, wherein the first and second HTMs each comprise a H₂-selective membrane selected from one or more of the following materials: supported or unsupported porous ceramics, dense cermets, dense metals, and/or dense metal alloys.
 8. The apparatus of claim 6, further comprising: a third HTM positioned upstream of the first HTM such that retentate from the third HTM can be fed to the first HTM.
 9. The apparatus of claim 8, wherein permeate from the third HTM comprises at least about 95% by volume hydrogen.
 10. The apparatus of claim 8, wherein the first, second and third HTMs each comprise a H₂-selective membrane selected from one or more of the following materials: supported or unsupported porous ceramics, dense cermets, dense metals, and/or dense metal alloys.
 11. The apparatus of claim 6, further comprising: a third HTM positioned upstream of the second HTM such that retentate from the third HTM can be fed to the second HTM.
 12. The apparatus of claim 6, wherein permeate from the third HTM comprises at least about 95% by volume hydrogen.
 13. The apparatus of claim 11, wherein the first, second and third HTMs each comprise a H₂-selective membrane selected from one or more of the following materials: supported or unsupported porous ceramics, dense cermets, dense metals, and/or dense metal alloys.
 14. A process for H₂ recovery from a H₂-containing gas stream from a gasifier in power and H₂ co-production plants, the process comprising: feeding a gas stream to a first hydrogen transport membrane (HTM); recovering H₂ permeate from the first HTM; feeding retentate from the first HTM to a second hydrogen transport membrane; feeding a first portion of nitrogen produced in an air separation unit (ASU) to the second HTM as a HTM permeate sweep stream; recovering a first H₂-N₂ fuel mixture from the second HTM and supplied to a gas turbine engine; feeding retentate from the second HTM to a third HTM; feeding a second portion of nitrogen produced in the ASU to the third HTM for use as a HTM permeate sweep stream; and recovering a second H₂-N₂ fuel mixture from the third HTM for use a duct burner fuel.
 15. The process of claim 14, wherein the H₂ permeate from the first HTM comprises at least about 95% by volume hydrogen.
 16. The process of claim 14, wherein the first, second and third HTMs each comprise a H₂-selective membrane selected from one or more of the following materials: supported or unsupported porous ceramics, dense cermets, dense metals, and/or dense metal alloys.
 17. The process of claim 14, wherein the first portion of ASU nitrogen is introduced into the second HTM at a pressure of equal to or greater than about 125 psia and the second portion of ASU nitrogen is introduced into the third HTM at a pressure of less than or equal to about 75 psia.
 18. The process of claim 14, wherein the second H₂-N₂ fuel mixture from the third HTM for use a duct burner fuel is at near atmospheric pressure of less than or equal to about 25 psia.
 19. The process of claim 14, wherein the retentate fed to the second HTM is at near-gasifier pressure between about 350 to 1000 psia.
 20. A process for H₂ recovery from a H₂-containing gas stream from a gasifier in power and H₂ co-production plants, the process comprising: feeding a first portion of the H₂-containing gas stream to a first hydrogen transport membrane (HTM); feeding a second portion of the H₂-containing gas stream to a second hydrogen transport membrane; feeding a first portion of nitrogen produced in an air separation unit (ASU) to the second HTM as a HTM permeate sweep stream; recovering H₂ permeate from the first HTM; recovering a first H₂-N₂ fuel mixture from the second HTM for use as a gas turbine fuel; feeding retentate from the first and second HTMs to a third HTM; feeding a second portion of nitrogen produced in the ASU to the third HTM for use as a HTM permeate sweep stream; and recovering a second H₂-N₂ fuel mixture from the third HTM for use a duct burner fuel.
 21. The process of claim 20, wherein the H₂ permeate from the first HTM comprises at least about 95% by volume hydrogen.
 22. The process of claim 20, wherein the first, second and third HTMs each comprise a H₂-selective membrane selected from one or more of the following materials: supported or unsupported porous ceramics, dense cermets, dense metals, and/or dense metal alloys.
 23. The process of claim 20, wherein the first portion of ASU nitrogen is introduced into the second HTM at a pressure of equal to or greater than about 125 psia and wherein the second portion of ASU nitrogen is introduced into the third HTM at a pressure of less than or equal to about 75 psia.
 24. The process of claim 20, wherein the second H₂-N₂ fuel stream from the third HTM for use a duct burner fuel is at near atmospheric pressure of less than or equal to about 25 psia.
 25. The process of claim 20, wherein the H₂-containing gas stream fed to the second HTM is at near-gasifier pressure of between about 350 to 1000 psia. 